Different structure of CO2 from hydrocarbon gases and oils has a significant impact on properties of CO2-oil miscible mixtures in comparison with “live” oil with dissolved hydrocarbon gases. We have systematically investigated velocity and density of CO2 with different oil (API) mixtures above their bubble point. The measurement condition is ranged with CO2 GOR up to 310L/L, temperature from 40°C to 100°C, and pressure from 20MPa to 100MPa. Based on our updated database we have developed preliminary models for the velocity and density of the CO2-oil miscible mixtures.

The Russkoe gas and oil field was discovered in 1968. No attempts to begin its commercial operation in the former USSR were and have been successful till the present time. The issue of economically attractive development of the Russkoe field is very urgent for TNK-BP since the field is a strategic oil asset to replenish company reserves. The field is located in the Arctic zone, in the north of the Tyumen Oblast, Russian Federation. Russkoe reserves are hard to recover, and the expected oil recovery factor is 14-15%. The main pay zone, PK 1-7, consists of unconsolidated poorly cemented sandstones with a high pelite fraction content. The reservoir is saturated with highly viscous oil (19 API), and low reservoir temperature (23°?) is predominant. Horizontal well profiles (over 500 m) are currently considered to be the most feasible ones from the economic point of view. The field is located in a hard-to-reach region with difficult logistics. With these conditions in view, correct selection of completion systems for sand control or containment is critical for assuring profitable operation of this asset from the point of view of maintaining well productivity, artificial lift and surface equipment loading. This article describes the TNK-BP process and experience in selecting the lower completion systems intended to suppress reservoir sand production in the Russkoe field. Different lower completion systems were tested during the pilot operations in 2006 - 2010. To reduce uncertainty, a set of laboratory tests of completion systems produced by a number of Russian and foreign manufacturers were conducted using the Russkoe field well fluid and core samples. The experience of leading servicing companies as well as experience of developing similar fields in the world was also taken into account. The article discusses in detail the approach chosen, decisions taken, current results, and lessons learned.

Natural Gas Hydrate (NGH) can be converted into CO2 hydrate by a ‘swapping mechanism’, serving double duty as a means of both sustainable energy source extraction and greenhouse gas sequestration. In particular, scant attention has been paid to the natural sediment clay portion in deep-sea gas hydrate, which is capable of storing a tremendous amount of NGH. The clay interlayer provides a unique chemical-physical environment for gas hydrates. Here, for the first time, we pull out methane from intercalated methane hydrates in a clay interlayer using CO2 and a CO2+N2 gas mixture.

INTRODUCTION

Natural gas hydrate (NGH) deposits in deep sea sediments or permafrost regions have strong potential as a next-generation energy source and as a global CO2 sequestration reservoir. Most NGH deposits are found under the seabed and are mainly structure I (sI) gas hydrates that holds methane gas as a guest molecule. Marine NGH-bearing sediments consist of fine-grained silt, sand, and clay (Clennell, 1999; Henry, 1999). NGH-bearing sand/silt/clay sediments contain pores and, particularly, interlayers in which NGH can exist (Yeon, 2009; Cygan, 2004). The replacement of methane and the more heavy gaseous components inside the water framework of NGH with CO2 has recently been suggested as a plausible and potential production approach that differs considerably from thermally stimulated and mechanically depressurized technologies (Lee, 2003; Park, 2006; Lu, 2007). A replacement method is a non-destructive process of swapping CH4 molecules in the hydrate cage for CO2 molecules, thus providing a dual mechanism of energy production and greenhouse gas sequestration (Lee, 2003; Park, 2006). The direct use of the CO2+N2 gas mixture (20.0 mol% of CO2 and 80 mol% of N2 to reproduce the flue gas from a power plant) instead of pure CO2 greatly improved the overall CH4 recovery rate and reduced the CO2 separation cost (Park, 2006; Shin, 2008). A complete understanding of the CO2 replacement mechanism.

Extra-heavy oil or bitumen wells are very difficult to start up and recover because of the high oil viscosity in cold production. It is necessary to get initial mobility by reducing the viscosity of oil or bitumen when the wells are drilled. Although there are mechanical ultrasonic stimulation technologies, the penetration of ultrasonic wave in the formation is very limited and their efficiency is not very good. Hot water or steam circulation is another option. However the heat loss in the wellbore is too significant to send enough heat to the targeted interval, specifically for deep reservoirs. Solvent could be a better option from both oil viscosity reduction and operation points of view. It can be injected into the well immediately after drilling for soaking, which is a convenient method to reduce viscosity without many complicated procedure as thermal methods. The concern for using solvent to reduce viscosity is selecting the optimal solvent. This paper studied the mixture of some typical extra-heavy oil and bitumen with solvent. After fully mixed with each other, viscosity reduction and potential precipitation have been investigated. Different solvents are discussed and recommended to reduce viscosity for new well start up and work-over.

A series of viscosity tests is conducted in the paper for heavy oil-solvent mixture under different temperatures to discuss the effect of three different solvents (diesel, ligarine and toluene) on viscosity reduction. Through these viscosity tests, the optimal solvent, temperature and solvent concentration for viscosity reduction are recommended. And it is found that after a solvent is placed in contact with heavy oil samples at any temperature in the range of 20 - 80C the reduction of viscosity can be significant. However, considering the economical effectiveness, diesel is not recommended. And 60-90 ligarine and toluene are better choices for starting up super heavy oil or bitumen wells. In addition, as to bitumen, due to its extremely high viscosity, using several times volume of solvent as the bitumen volume still can't have the viscosity reduce to a desired value. So these solvents tested in the experiments are not recommended for bitumen well starting up after drilling.